Method for Pumping Hydrocarbons

ABSTRACT

A method of pumping a hydrocarbon fluid from a wellbore ( 4 ) and a hydrocarbon completion ( 1 ) implementing the methodology is described. The method comprises deploying a tubing string ( 7 ) and a first pump system ( 15 ), in fluid communication with the tubing string, within a wellbore. The first pump system is employed to generate a production fluid ( 17 ) by heating the hydrocarbon fluid as it is pumped into the tubing string so as to form a counter current heat exchanger between the production fluid within the tubing string and the hydrocarbon fluid located within the wellbore. The counter current heat exchanger provides a means for preheating the hydrocarbon fluid before it reaches the first pump system. As a result the viscosity of the hydrocarbon fluid is reduced thus making it easier to pump to the surface. The method finds particular application within horizontal, high angle or vertical wells in heavy or extra heavy oil fields.

The present invention relates to the field of hydrocarbon exploration. More specifically, the present invention concerns a method of pumping hydrocarbons that finds particular application for use with heavy and extra heavy fluids commonly found within the field of hydrocarbon exploration.

The definition of heavy and extra heavy oil is not strictly defined within the art. For the purposes of the following discussion the term heavy oil will be used to refer to a hydrocarbon fluid mixtures or emulsions with a viscosity between 1,000 cP (centi-Poise) and 20,000 cP while the term extra heavy oil will be used to refer to a hydrocarbon fluid mixtures or emulsions with a viscosity greater than 20,000 cP.

Horizontal drilling and horizontal wells have transformed the productivity of many conventional oil & gas wells by providing considerably greater reservoir inflow capability compared to vertical and deviated wells. Generally, horizontal wells are formed by initially drilling a vertical section to a specified depth. The high angle or horizontal section of the well is then drilled at a depth to maximise the contact between the wellbore and the reservoir. Increasing the contact between the wellbore and the reservoir can provide greater inflow potential. Long horizontal sections two kilometres or more are known in the art.

The above horizontal drilling techniques have been successfully employed by those skilled in the art in order to extract hydrocarbons. However, when deployed with heavy oil and extra heavy oil reservoirs the results have been poor due to the effects of friction loss and pseudo-plastic “gelling” of the reservoir fluids within the wellbore. In a long horizontal wellbore employed with a heavy oil reservoir, up to 90% of the theoretical inflow potential may be lost due to friction loss and pseudo-plastic “gelling”.

In order to improve the production of heavy oils some operators have experimented with employing larger diameter horizontal wellbores (e.g. 12¼″ (311.15 mm) bore cased with 9⅝″ (234.32 mm) casing instead of the normal 8½″ (215.90 mm) bore cased with 7″ (177.80 mm) casing). However, such wells are technically challenging, very expensive to drill and case and have only had limited beneficial effect. As a result, long horizontal wells are not proved effective in heavy and extra-heavy oil fields.

A second solution to this problem is for operators to drill multiple short horizontal wells, perhaps 100 metres in length. These wells may be drilled in a “crow's foot” or “herring bone” configuration or equivalent array structure to reduce the problems associated with a long wellbore. However, as appreciated by those skilled in the art, the drilling of multiple wells significantly increases the production costs for heavy oils and extra-heavy oils.

It is frequently required when exploring for hydrocarbons to provide artificial lift to the production fluid e.g. when extracting hydrocarbons from an oil bed it may be required to employ the assistance of a pump when the pressure of the hydrocarbon deposit is insufficient to bring the hydrocarbons to the surface. Some examples of such pumps known in the art include Electric Submersible Pumps (ESP), Progressing Cavity Pumps (PCP) or positive displacement pumps; centrifugal pumps; single helix pumps; and dual-helix axial or compressor pumps.

Including a pump system with the above described wellbore arrangements may help heavy oil and extra-heavy oil production for some reservoirs. However, other factors exists which still limit the levels of heavy oil and extra-heavy oil that can be extracted. By way of example, the preferred pump for such production is an Electric Submersible Pumps (ESP).

When an ESP is employed with within a wellbore it is required to be deployed at a lesser depth (i.e. nearer the surface of the wellbore) than the wellbore perforations in order to allow the production fluid to cool the motor and pump modules as it passes over the outer surface of ESP. This configuration has an inherent benefit for the production of heavy oil and extra-heavy oil in that heat is transferred from the ESP to the production fluid as it passes into the tubing string thus making it less viscous and thus easier to pump to the surface. The benefit of heating a heavy oil with an ESP is known in the art, see for example US patent numbers U.S. Pat. No. 8,037,936; U.S. Pat. No. 6,318,467 and U.S. Pat. No. 6,564,874.

However with this arrangement the high viscosity of the heavy oil in the reservoir itself is found to cause preferential production from the “heel” end of the reservoir with little or no production from the ‘toe’ end. As reservoir fluid viscosity increases, this effect becomes more severe. Typically, only the first 50 metres of a reservoir will contribute to the production process with such an arrangement. In these circumstances operators are again forced to consider multiple wells and the associated increases in the production costs.

In addition, although ESP systems have been demonstrated to be are capable of pumping fluids with viscosities up to around 1,500 cP to 2,000 cP, the performance of an ESP is greatly reduced when operating with a fluid at such viscosities. The ESPs known in the art are simply unable to pump fluids with viscosities greater than 2,000 cP and so are not suitable for use with extra-heavy oils or even many heavy oils.

It is recognised in the present invention that considerable advantage is to be gained in a completion design that is capable of producing heavy and extra heavy oil from wells and in particular long horizontal or high angle wells.

SUMMARY OF INVENTION

According to a first aspect of the present invention there is provided a method of pumping a hydrocarbon fluid from a wellbore the method comprising:

-   -   deploying a tubing string within the wellbore;     -   deploying within the wellbore a first pump system that is in         fluid communication with the tubing string;     -   employing the first pump system to generate a production fluid         by heating the hydrocarbon fluid as it is pumped into the tubing         string; and     -   forming a counter current heat exchanger between the production         fluid within the tubing string and the hydrocarbon fluid located         within an annulus between the tubing string and the wellbore.

The formation of the counter current heat provides a means for pre-heating the hydrocarbon fluid before it reaches the first pump system i.e. as it flows into the wellbore and alongside the tubing string towards the pump system. As a result the viscosity of the hydrocarbon fluid is reduced thus making it easier to pump to the surface. The method finds particular application within horizontal, high angle or vertical wells in heavy or extra heavy oil fields. The described method also acts to minimise the deposition of wax and other materials within the well.

The hydrocarbon fluid may comprise a viscosity greater than 1,000 cP. Preferably the hydrocarbon fluid comprises a viscosity greater than 2,000 cP. i.e. the hydrocarbon fluid comprises a heavy oil.

Most preferably the hydrocarbon fluid comprises an extra heavy oil i.e. a hydrocarbon fluid mixture or emulsion with a viscosity greater than 20,000 cP.

Preferably the first pump system is deployed such that one or more wellbore perforations are located between the first pump system and the surface of the wellbore.

Most preferably the first pump system is located 75% to 95% of the way along the wellbore. This arrangement helps to maximise the surface area of the counter current heat exchanger.

The hydrocarbon fluid may be heated to over 150° C. as it is pumped into the tubing string assembly i.e. the first pump system operates at a fluid discharge temperature of over 150° C. The hydrocarbon fluid may be heated to over 300° C. as it is pumped into the tubing string. Running the pump system “hot” provides a means for improving the efficiency of the counter current heat exchanger.

The method may further comprise changing the operating parameters of a pump assembly of the pump first system so as to provide a means for optimising the pumping of the hydrocarbon fluid. This may involve changing the operating frequency of the pump assembly and or altering the operating point of the pump assembly along its head capacity curve.

The method may further comprise deploying a first diverter located between the first pump system and the tubing string. Most preferably the method further comprises deploying a first bypass tubing with the first diverter. In this arrangement the first diverter provides a means for selectively establishing fluid communication between the first pump system and or the first bypass tubing and the tubing string.

Optionally the method further comprises deploying a second pump system within the wellbore that is in fluid communication with the tubing string.

Preferably the second pump system is in fluid communication with the tubing string via the first bypass tubing.

The method may further comprise deploying a second diverter located between the second pump system and the tubing string. The method may further comprise deploying a second bypass tubing with the second diverter. In this arrangement the second diverter provides a means for selectively establishing fluid communication between the second pump system and or the second bypass tubing and the tubing string.

Employing two or more pump systems provides a unique capability for selectively producing different parts of the reservoir at different rates. These methods also provide a unique capability to perform a balanced circulation (i.e. in hydraulic balance, even with a depleted reservoir) for placement of well servicing materials e.g. water shut-off gels, treatment slurries, etc.

According to a second aspect of the present invention there is provided a hydrocarbon completion suitable for pumping a hydrocarbon fluid from a wellbore the completion comprising:

-   -   a tubing string deployed within the wellbore     -   a first pump system deployed within the wellbore that is in         fluid communication with the tubing string         wherein the first pump system is employed to generate a         production fluid by heating the hydrocarbon fluid as it is         pumped into the tubing string and the production fluid within         the tubing string forms a counter current heat exchanger with         the hydrocarbon fluid located within an annulus between the         tubing string and the wellbore.

Preferably the pumps system comprises a pump assembly and a motor.

Most preferably the pumps system further comprises a cooling shroud that depends from the pump assembly so as to define a flow path that requires the hydrocarbon fluid to pass over the motor before entering the pump assembly

A protector seal module may be located between the pump assembly and the motor.

The hydrocarbon fluid may be heated to over 150° C. as it is pumped into the tubing string assembly i.e. the first pump system operates at a fluid discharge temperature of over 150° C. The hydrocarbon fluid may be heated to over 300° C. as it is pumped into the tubing string. Running the pump system “hot” provides a means for improving the efficiency of the counter current heat exchanger.

The motor may comprise a dual-helix axial pump.

Preferably the hydrocarbon completion further comprises a control system that provides a means for changing the operating parameters of a pump assembly of the pump first system so as to provide a means for optimising the hydrocarbon fluid production from the wellbore. The control system may provide a means for changing the operating frequency of the pump assembly and or for controlling a choke so as to alter the operating point of the pump assembly along its head capacity curve.

The hydrocarbon completion may further comprise a first diverter located between the first pump system and the tubing string. Most preferably the hydrocarbon completion further comprises a first bypass tubing connected to the first diverter. In this arrangement the first diverter provides a means for selectively establishing fluid communication between the first pump system and or the first bypass tubing and the tubing string.

Optionally the hydrocarbon completion further comprises a second pump system within the wellbore that is in fluid communication with the tubing string.

Preferably the second pump system is in fluid communication with the tubing string via the first bypass tubing.

The hydrocarbon completion may further comprise a second diverter located between the second pump system and the tubing string. The hydrocarbon completion may further comprise a second bypass tubing connected to the second diverter. In this arrangement the second diverter provides a means for selectively establishing fluid communication between the second pump system and or the second bypass tubing and the tubing string.

Embodiments of the second aspect of the invention may comprise features to implement the preferred or optional features of the first aspect of the invention or vice versa.

According to a third aspect of the present invention there is provided a method suitable for pumping a hydrocarbon fluid having a viscosity greater than 2,000 cP from a wellbore the method comprising:

-   -   deploying a tubing string within the wellbore;     -   deploying within the wellbore a first pump system that is in         fluid communication with the tubing string;     -   employing the first pump system to generate a production fluid         by heating the hydrocarbon fluid as it is pumped into the tubing         string; and     -   forming a counter current heat exchanger between the production         fluid within the tubing string and the hydrocarbon fluid located         within an annulus between the tubing string and the wellbore.

Embodiments of the third aspect of the invention may comprise features to implement the preferred or optional features of the first or second aspects of the invention or vice versa.

BRIEF DESCRIPTION OF DRAWINGS

Aspects and advantages of the present invention will become apparent upon reading the following detailed description and upon reference to the following drawings in which:

FIG. 1 presents a section view of a horizontal reservoir with a single pump hydrocarbon completion in accordance with an embodiment of the present invention;

FIG. 2 presents a schematic representation of the pump system of FIG. 1;

FIG. 3 presents a cross-sectional assembled view of a pump assembly of the pump system of FIG. 2;

FIG. 4 presents a section view of the horizontal section of a horizontal well showing the fluid flow paths and heat transfer paths;

FIG. 5 presents a section view a horizontal reservoir with a multiple pump hydrocarbon completion in accordance with an embodiment of the present invention;

FIG. 6 presents a section view of an electro-hydraulic diverter employed within the multiple pump hydrocarbon completion of FIG. 5; and

FIG. 7 presents a section view of a horizontal reservoir with an alternative multiple pump hydrocarbon completion in accordance with an embodiment of the present invention.

DETAILED DESCRIPTION

In the description that follows the terms “upper”, “lower”, “downward” and “upward” are relative terms used herein to indicate directions in a wellbore, with “upper” and equivalents referring to the direction along the wellbore towards the surface, and “lower” and equivalents referring to the direction towards the bottom hole. It will be appreciated that the invention has application to deviated and lateral wellbores.

A hydrocarbon completion in accordance with an embodiment of the present invention, and generally depicted by reference numeral 1, will now be described with reference to FIGS. 1 to 4. The completion design 1 can be seen deployed with a substantially horizontal reservoir 2 comprising heavy and or extra heavy oil 3.

The hydrocarbon completion 1 can be seen to comprise a well 4 formed from a casing 5, which is cemented into a wellbore 6. The casing 5 may comprise perforated casing or screen installed casing as is known to those skilled in the art. The horizontal section of the well 4 b is at a depth to maximise the contact between the wellbore 6 and the heavy or extra heavy oil 3 within the reservoir 2.

A tubing string 7 is supported via a tubing hanger 8 located at the surface 9. The tubing string defines an annulus 10 with the surrounding wellbore. Also located at the surface 9 is a wellhead 11 comprising a production choke 12, a control system 13 and a production facility 14.

A pump system 15, which is connected to tubing string 7, is located within the horizontal section of the well 4 b. As described in further detail below, it is preferable for as many well perforations 16 to lie between the pump system 15 and the surface 9 i.e. the pump system is located further into the well 4 than one or more of the well perforations 16. Preferably, the pump system 15 is located 75% to 95% of the way along the horizontal section of the well 4 b.

The pump system 15 is employed to artificially lift the production fluid 17 up the tubing string 7 and through the wellhead 11, where the fluid 17 is then controlled and distributed to the production facility 14. The pump system 15 is controlled at surface 9 by the control system 13 connected to the pump system 15 by a down-hole electrical cable 18.

Further detail of the pump system 15 will now be described with reference to FIGS. 2 and 3. From FIG. 2 the pump system 15 can be seen to comprise a motor 19 and a pump assembly 20. Preferably a protector seal module 21 is located between the motor 19 and the pump assembly 20. A cooling shroud 22 depends from the pump assembly 20 so as to define a flow path that requires the heavy oil 3 to pass over the motor 19 before entering the pump assembly 20.

The pump assembly 20, as shown schematically in FIG. 3, is preferably a pump assembly of the type described by the inventor within PCT publication number WO 2012/013973. Here the pump assembly 20 can be seen to comprise a rotor 23 which is surrounded by an annular stator 24 that is arranged to be coaxial with, and extend around, the rotor 23. The rotor 23 is externally screw-threaded in a right-handed sense by the provision of three rotor vanes 25 located on its external surface. The stator 24 is correspondingly internally screw-threaded in a left-handed sense through the provision of three stator vanes 26 located on its internal surface. The rotor vanes 25 and the stator vanes 26 are threaded so as to exhibit equal pitch and have radial heights such that they approach each other sufficiently closely so as to provide rotor channels 27 and stator channels 28 within which a fluid can be retained for longitudinal movement upon rotation of the rotor 23. In the presently described embodiment the rotor channels 27 and stator channels 28 are all of the same length and cross sectional area.

The pump assembly 20 can be seen to further comprise a cylindrical housing 29 within which the remaining components are located. The rotor 23 is connected to the motor 19 by means of a central shaft 30 such that operation of the motor 19 induces relative rotation between the rotor 23 and the stator 24.

An inlet 31 and an outlet 32 of the pump assembly 20 are defined by the location of two bearings 33 separated along the longitudinal axis of the device. The bearings 33 assist in securing the rotor 23 and the stator 24 within the cylindrical housing 29 while reducing the effects of mechanical vibration thereon during normal operation. The inlet 31 and outlet 32 are obviously determined by the orientation in which the pump assembly 20 is operated i.e. with reference to FIG. 3 the fluid flow is substantially along the positive z-axis but can be reversed depending on whether the rotation of the rotor 23 is clockwise or anticlockwise.

By setting:

-   -   1) the size of a radial gap between the rotor vanes 25 and the         stator vanes 26;     -   2) the relative heights of the rotor vanes 25 and the stator         vanes 26; and     -   3) the relative thicknesses of rotor vanes 25 and the stator         vanes 26,         the pump assembly 20 provides an efficient and robust means for         pumping high viscosity and/or multiphase fluids. Significantly,         the pump assembly design allows it to be run at operating         temperature as high as 400° C., almost twice the highest         operating temperatures achievable with an ESP. This high         operating temperature makes the pump assembly 20 particularly         suitable for use within the presently described completion 1, as         will be described in further detail below.

The operation of the completion 1 of FIG. 1 will now be described with reference to FIG. 4 which shows a section view of the horizontal section 4 b of a horizontal well showing both fluid flow paths (as generally indicated by the direction of the arrows) and heat transfer paths (as generally indicated by the size of the arrow heads, larger arrow heads represents a higher fluid temperature at the location of the arrow).

In the first instance the heavy oil 3 contained within the reservoir 2 is at a typical temperature of ˜55° C. and viscosity of ˜5,000 cP. The heavy oil 3 flows from the reservoir 2 into the wellbore 6, as represented by arrows 34.

When the pump system 15 is activated heavy oil 3 is pumped into the tubing string 7, as described above, so as to produce a production fluid 17 that has a direction of flow towards the surface 9, as indicated by arrows 35. The pump assembly 20 is run at a fluid discharge temperature of ˜300° C., and as will be described below, since a pre-warmed fluid flows past the motor 19 in a turbulent flow a significant enhancement of the motor 19 cooling process is observed. The produced fluid then passes through the pump assembly 20 resulting in the pressure being considerably increased (potential energy). Therefore, by the time the heavy oil 3 has entered the shroud 22, passed over the motor 19 and the protector seal module 21 and through the pump assembly 20 into the tubing string 7 it has been heated to a temperature of ˜150° C. and has a viscosity of ˜50 cP. It is obviously significantly easier for the pump system 15 to pump the production fluid 17 towards the surface 9 when it exhibits a significantly lower viscosity as it flows through the tubing string 7.

It will be appreciated by those skilled in the art that a production fluid 17 having a temperature of ˜150° C. cannot be easily handled by an operator at the surface 9. Indeed in a normal production completion this temperature would be regarded as unacceptable since it is desirable for the temperature of the production fluid 17 to be below 100° C. at the surface 9 so as to avoid the problematic effects of flash evaporation of water from the production fluid 17 and any consequent salt deposition.

As can be seen from FIG. 4, the design of completion 1 is such that the production fluid 17 in the tubing string 7 cools as it is pumped towards the surface 9 by transferring heat to the surrounding heavy oil 3 located in the annulus 10 of the wellbore 6 and the reservoir 2.

In the presently described embodiment, the production fluid 17 cools from ˜150° C. at it leaves the pump assembly to ˜90° C. by the time it reaches the surface 9. The viscosity of the production fluid 17 thus correspondingly increases from ˜50 cP to ˜250 cP.

The production fluid 17 in the tubing string 7 however simultaneously acts as a counter current heat exchanger with the annulus fluid flow, as indicated by arrows 36. This heating of the fresh reservoir production commences immediately on the oil contacting the hot tubing string 7. This heating is continuous as the oil flows alongside the tubing string 7 (but counter to the flow within the tubing string 7). As a result, the heavy oil 3 is heated from the reservoir temperature of ˜55° C. to ˜100° C. before it enters the pump system 15. The viscosity of the heavy oil 3 within the annulus fluid flow 36 thus falls from ˜5,000 cP to ˜200 cP as a result of this counter current heat exchange mechanism.

The pump system 15 can be employed so as to optimise the operation of the completion 1, as and when required. There are two available options for this which can be employed independently or in conjunction with each other.

The first option involves employing the control system 13 to change the operating frequency of the pump assembly 20. By changing the operating frequency of the pump assembly 20 the operating temperature and temperature rise created within the pump system 15 can be adjusted. In general, if the completion 1 is running too hot then the operating frequency of the pump assembly 20 is lowered. Similarly, if the completion 1 is running too cold then the operating frequency of the pump assembly 20 is increased.

The second option involves adjusting the choke 12 within the wellhead 11 so as to alter the operating point of the pump assembly 20 along its head capacity curve and efficiency capacity curve.

These optimisation techniques allow for complete control over the temperature and heat transfer characteristics of the fluids within the completion 1. For example, if some degree of tubing fouling occurs such that heat transfer is less effective, the pump assembly 20 can be adjusted to re-optimise the thermal behaviour of the well 4. Alternatively, as the water cut rises, the Specific Heat (thermal capacity) of the fluid will change coupled with a possible change in fluid viscosity. The operation of the well 4 can then be re-optimised by adjusting the pump assembly 20 operating frequency and or operating point of the pump assembly 20 on the head capacity curve.

Multiple Pump Hydrocarbon Completions

It will be appreciated that the above techniques are not limited to the employment of a single pump system 15. Two multiple pump hydrocarbon completions will now be described with reference to FIGS. 5, 6 and 7.

FIG. 5 presents a section view of a horizontal reservoir 2 with a multiple pump hydrocarbon completion, as depicted generally by reference numeral 1 b. The completion 1 b comprises many of the elements described above in relation to the single pump completion 1 of FIG. 1 and these elements are therefore marked with the same reference numerals. However, in the presently described embodiment the single pump system 15 is replaced by a multiple pump system 37. For ease of understanding, the presently described embodiment has a multiple pump system 37 that comprises two pump modules, 38 a and 38 b. However, it will be appreciated by those skilled in the art that in alternative embodiments the number of pump modules 38 employed may be increased and that the actual number employed will depend on the well 4 and reservoir 2 characteristics.

Each of the pump modules 38 a and 38 b can be seen to comprise a pump system 15 a and 15 b and a bypass tubing 39 a and 39 b both of which are connected to an associated electro-hydraulic diverter 40 a and 40 b. As can be seen from FIG. 6 the electro-hydraulic diverters 40 a and 40 b comprise a main tubing 41 and an integrated secondary tubing 42 such that it forms a substantially Y-shape. The main tubing comprises a first 43 and a second aperture 44 for the diverter 40 while a third aperture 45 is provided by the integrated secondary tubing 42.

Each electro-hydraulic diverter 40 further comprises an internal control valve 46 that provides a means for selecting between four modes of operation for the diverter 40, namely:

-   -   1) the internal control valve 46 is configured such that both         the second 44 and third apertures 45 are open to allow fluid to         flow through;     -   2) the internal control valve 46 is configured such that the         second aperture 44 is sealed to prevent fluid flow while the         third aperture 45 is open to allow fluid flow;     -   3) the internal control valve 46 is configured such that the         third aperture 45 is sealed to prevent fluid flow while the         second aperture 44 is open to allow fluid flow; and     -   4) the internal control valve 46 is configured such that both         the second 44 and third apertures 45 are closed to prevent fluid         to flow through.

With regards to the pump module 38 a the first opening 43 is arranged to be in fluid communication with the tubing string 7, the second opening 44 with the bypass tubing 39 a and the third opening 45 with the pump system 15 a. The arrangement for pump module 38 b, and indeed any additional pump modules 38, is similar but for the fact that the first opening 43 is arranged to be in fluid communication with the bypass tubing 39 a of the previous pump module 38 a.

FIG. 7 presents a section view of a horizontal reservoir 2 with an alternative multiple pump hydrocarbon completion, as depicted generally by reference numeral 1 c. The completion 1 b comprises many of the elements described in relation to the multiple pump hydrocarbon completion 1 b of FIG. 5 and these elements are marked with the same reference numerals. In this embodiment however the electro-hydraulic diverter 40 b connects only to pump system 15 b i.e. it does not connect to an associated bypass tubing. Therefore, unlike multiple pump hydrocarbon completion 1 b, multiple pump hydrocarbon completion 1 c does not provide a means to allow logging or intervention tools to reach the bottom of the well 4.

The employment of the electro-hydraulic diverters 40 allow for the multiple pump hydrocarbon completions la and lb to operate in a range of production modes and well service modes as will now be described in further detail.

Production Modes

1) Production from Upper Pump System 15 a

In this mode electro-hydraulic diverter 40 a would be configured such that that internal control valve 46 a operates in its second mode of operation i.e. the second aperture 44 a is sealed while the third aperture 45 a is open while the electro-hydraulic diverter 40 b would be configured such that that internal control valve 46 b operates in its fourth mode or operation i.e. both the second 44 b and third apertures 45 b are closed to prevent fluid flowing through. Upper pump system 15 a would then be operated in a forward pumping regime.

2) Production from Lower Pump System 15 b

Here electro-hydraulic diverter 40 b would be configured such that that internal control valve 46 b operates in its second mode of operation i.e. the second aperture 44 b is sealed while the third aperture 45 b is open. However, in this production mode the electro-hydraulic diverter 40 a would be configured such that that internal control valve 46 a operates in its third mode of operation i.e. the second aperture 44 a is open while the third aperture 45 a is sealed to stop re-circulation of the production fluid 17. The lower pump system 15 b would then be operated in a forward pumping regime.

3) Production from Upper & Lower Pump Systems 15 a and 15 b

In this production mode the electro-hydraulic diverter 40 a would be configured such that that internal control valve 46 a operates in its first mode of operation i.e. both the second 44 a and third apertures 45 a are open to allow fluid to flow through while the electro-hydraulic diverter 40 b would be configured such that that internal control valve 46 b operates in its second mode of operation i.e. the second aperture 44 b is sealed while the third aperture 45 b is open. Both the upper 15 a and lower 15 b pump systems would then be operated in a forward pumping regime.

Well Service Modes

1) Reverse Pumping of Production Fluid 17 from Upper Pump System 15 a

In this mode of operation the internal control valve 46 a of electro-hydraulic diverter 40 a would be configured to operate in the second mode of operation such that the second aperture 44 a is sealed to prevent fluid flow while the third aperture 45 a is open to allow fluid flow. The electro-hydraulic diverter 40 b would be configured such that that internal control valve 46 b operates in its fourth mode or operation i.e. both the second 44 b and third apertures 45 b are closed to prevent fluid flowing through. The upper pump system 15 a would then be operated in a reverse pumping regime, which will allow hot produced fluid from tubing string 7 to wash the horizontal well 4.

2) Reverse Pumping of Production Fluid 17 from Lower Pump System 15 b

The internal control valve 46 b of electro-hydraulic diverter 40 b would be configured to operate in the second mode of operation such that the second aperture 44 b is sealed to prevent fluid flow while the third aperture 45 b is open to allow fluid flow. The electro-hydraulic diverter 40 a would be configured such that that internal control valve 46 a operates in its third mode or operation i.e. the third aperture 45 a is sealed to prevent fluid flow while the second aperture 44 a is open. Lower pump system 15 b would then be operated in a reverse pumping regime.

It will be appreciated that the above described well service modes could be controlled such that alternating between forward and reverse pumping could be employed to provide an effective well service program.

3) Circulation of Production Fluid 17 or Stimulation Fluid between Upper & Lower Pump Systems 15 a and 15 b

The internal control valve 46 a of electro-hydraulic diverter 40 a would be configured to operate in the first mode of operation such that both the second 44 a and third 45 a apertures are open to allow fluid flow. The internal control valve 46 b of electro-hydraulic diverter 40 b would be configured to operate in the second mode of operation such that the second aperture 44 b is sealed to prevent fluid flow while the third aperture 45 b is open to allow fluid flow. The production choke 12 in the well head 11 would also be closed so as to allow pump systems 15 a and 15 b to circulate fluid in horizontal well 4 when the upper pump system 15 a is operated in a reverse pumping regime and lower pump system 15 b is operated in a forward pumping regime, or vice versa.

The above methods and apparatus have particular application in improving the efficiency of production of heavy and extra heavy oils. The apparatus may comprise a single pump system or multiple pump system's combined with ‘intelligent completion’ technology so as to allow for its use in a range of production and well servicing modes.

Although not so limited, the described methods and apparatus find particular application within horizontal, high angle or vertical wells in heavy or extra heavy oil fields. It is particularly advantageous to arrange these wells to have a long inflow section located within the reservoir.

The completion designs allow for full and optimally efficient use of all of the electrical energy supplied to the well. This energy may be used to provide hydraulic power to the pumped fluids so as to controllably increase the tubing string, wellbore annular and reservoir fluid temperature. Increasing the fluid temperature substantially reduces the viscosity of the heavy and extra heavy oil, thus reducing the tubing string and wellbore annular friction.

A direct result of this arrangement is that most of the oil is pre-heated as it flows into the wellbore and alongside the tubing string towards the pump intake (whether single or multiple pump embodiments). A shroud is preferably incorporated within the pump system so as to allow the hydrocarbon fluid in the annulus 10 to flow past the motor. Therefore heavy and extra heavy oils may achieve a viscosity reduction typically greater than 95% before they enter the pump intake.

The pre-warmed oil provides a much improved cooling for the pump system motor as well as increasing the hydraulic efficiency of the pump assembly.

It is recognised that the wellbore cross-section area is reduced by the presence of the tubing string and power cable(s) but this is entirely mitigated by the substantially reduced fluid viscosity of the heavy and extra heavy oil and the reduced effects of wellbore annular and tubular string friction.

The described completion arrangements also act to minimise the deposition of wax and other materials within the well. However, in the event of such deposition the completion designs can be operated in easily configured modes so as to perform a hot oil or hot water wash on the inflow sections or a hot well stimulation fluid wash.

The above described multiple pump systems provide a unique capability for selectively producing different parts of the reservoir at different rates. These systems also provide a unique capability to perform a balanced circulation (i.e. in hydraulic balance, even within a depleted reservoir) for placement of well servicing materials e.g. water shut-off gels, treatment slurries, etc. traditionally these can be problematic to deploy on long horizontal wells (and virtually impossible within heavy and extra heavy oil wells) as the fluid always enters the reservoir at the heel or the tubing shoe. Accurate ‘placement’ of fluids is therefore not possible. Utilising the above described methods and apparatus the pump systems can be used to circulate treatment fluids or slurries to a precise location by a combination of forward and reverse pumping. This occurs irrespective of depleted reservoir pressure, such that accurate placement is achieved without hardware intervention.

As a direct consequence of the present invention, heavy and extra heavy oil fields can now be developed using efficient and effective long horizontal wells with full and appropriate inflow and production developed along the entire length of the horizontal section. Of further advantage is that the completion designs also includes measures to deal with wax precipitation, emulsions, sand production and other operational issues without the need for further well intervention.

A method of pumping a hydrocarbon fluid from a wellbore and a hydrocarbon completion implementing the methodology is described. The method comprises deploying a tubing string and a first pump system within a wellbore, the first pump system being arranged to be in fluid communication with the tubing string. The first pump system is further arranged such that a counter current heat exchanger is formed between a production fluid pumped by the first pump system within the tubing string and the hydrocarbon fluid located within the wellbore. The formation of the counter current heat provides a means for pre-heating the hydrocarbon fluid before it reaches the first pump system. As a result the viscosity of the hydrocarbon fluid is reduced thus making it easier to pump to the surface. The method finds particular application within horizontal, high angle or vertical wells in heavy or extra heavy oil fields.

The foregoing description of the invention has been presented for purposes of illustration and description and is not intended to be exhaustive or to limit the invention to the precise form disclosed. The described embodiments were chosen and described in order to best explain the principles of the invention and its practical application to thereby enable others skilled in the art to best utilise the invention in various embodiments and with various modifications as are suited to the particular use contemplated. Therefore, further modifications or improvements may be incorporated without departing from the scope of the invention as defined by the appended claims. 

1. A method of pumping a hydrocarbon fluid from a wellbore the method comprising: deploying a tubing string within the wellbore; deploying within the wellbore a first pump system that is in fluid communication with the tubing string; employing the first pump system to generate a production fluid by heating the hydrocarbon fluid as it is pumped into the tubing string; and forming a counter current heat exchanger between the production fluid within the tubing string and the hydrocarbon fluid located within an annulus between the tubing string and the wellbore to heat the hydrocarbon fluid before it enters the pump system.
 2. A method of pumping a hydrocarbon fluid as claimed in claim 1 wherein the hydrocarbon fluid comprises a fluid having a viscosity of greater than 1,000 cP.
 3. A method of pumping a hydrocarbon fluid as claimed in claim 1 wherein the hydrocarbon fluid comprises a fluid having a viscosity of greater than 2,000 cP.
 4. A method of pumping a hydrocarbon fluid as claimed in claim 1 wherein the hydrocarbon fluid comprises a fluid having a viscosity of greater than 20,000 cP.
 5. A method of pumping a hydrocarbon fluid as claimed in claim 1 wherein the first pump system is deployed such that one or more wellbore perforations are located between the first pump system and the surface of the wellbore.
 6. A method of pumping a hydrocarbon fluid as claimed in claim 1 wherein the first pump system is located 75% to 95% of the way along the wellbore.
 7. A method of pumping a hydrocarbon fluid as claimed in claim 1 wherein the hydrocarbon fluid is be heated to over 150° C. as it is pumped into the tubing string assembly.
 8. A method of pumping a hydrocarbon fluid as claimed in claim 1 wherein the hydrocarbon fluid is be heated to over 300° C. as it is pumped into the tubing string assembly.
 9. A method of pumping a hydrocarbon fluid as claimed in claim 1 wherein the method further comprises changing the operating parameters of a pump assembly of the pump first system so as to provide a means for optimizing the pumping of the hydrocarbon fluid.
 10. A method of pumping a hydrocarbon fluid as claimed in claim 9 wherein the method comprises changing the operating frequency of the pump assembly.
 11. A method of pumping a hydrocarbon fluid as claimed in claim 9 wherein the method comprises altering the operating point of the pump assembly along its head capacity curve.
 12. A method of pumping a hydrocarbon fluid as claimed in claim 1 wherein the method further comprises deploying a first diverter located between the first pump system and the tubing string so as to provide a means for selectively establishing fluid communication between the first pump system and the tubing string.
 13. A method of pumping a hydrocarbon fluid as claimed in claim 12 wherein the method further comprises deploying a first bypass tubing with the first diverter so as to provide a means for selectively establishing fluid communication between the first bypass tubing and the tubing string.
 14. A method of pumping a hydrocarbon fluid as claimed in claim 1 wherein the method further comprises deploying a second pump system within the wellbore that is in fluid communication with the tubing string.
 15. A method of pumping a hydrocarbon fluid as claimed in claim 14 wherein the second pump system is in fluid communication with the tubing string via the first bypass tubing.
 16. A method of pumping a hydrocarbon fluid as claimed in claim 14 wherein the method further comprises deploying a second diverter located between the second pump system and the tubing string so as to provide a means for selectively establishing fluid communication between the second pump system and the tubing string.
 17. A method of pumping a hydrocarbon fluid as claimed in claim 16 wherein the method further comprises deploying a second bypass tubing with the second diverter so as to provide a means for selectively establishing fluid communication between the second bypass tubing and the tubing string.
 18. A hydrocarbon completion suitable for pumping a hydrocarbon fluid from a wellbore the completion comprising: a tubing string deployed within the wellbore a first pump system deployed within the wellbore that is in fluid communication with the tubing string, wherein the first pump system is employed to generate a production fluid by heating the hydrocarbon fluid as it is pumped into the tubing string and the production fluid within the tubing string forms a counter current heat exchanger with the hydrocarbon fluid located within an annulus between the tubing string and the wellbore to heat the hydrocarbon fluid before it enters the pump system.
 19. A hydrocarbon completion as claimed in claim 18 wherein the first pump system comprises a pump assembly and a motor.
 20. A hydrocarbon completion as claimed in claim 19 wherein the first pump system further comprises a cooling shroud that depends from the pump assembly so as to define a flow path that requires the hydrocarbon fluid to pass over the motor before entering the pump assembly.
 21. A hydrocarbon completion as claimed in claim 19 wherein a protector seal module is located between the pump assembly and the motor.
 22. A hydrocarbon completion as claimed in claim 18 wherein the motor comprises a dual-helix axial pump.
 23. A hydrocarbon completion as claimed in claim 18 wherein the hydrocarbon completion further comprises a control system that provides a means for changing the operating parameters of a pump assembly of the pump first system so as to optimize the hydrocarbon fluid production from the wellbore.
 24. A hydrocarbon completion as claimed in claim 23 wherein the control system provide a means for changing the operating frequency of the pump assembly.
 25. A hydrocarbon completion as claimed in claim 23 wherein the control system provides a means for controlling a choke so as to alter the operating point of the pump assembly along its head capacity curve.
 26. A hydrocarbon completion as claimed in claim 18 wherein the hydrocarbon completion further comprises a first diverter located between the first pump system and the tubing string.
 27. A hydrocarbon completion as claimed in claim 26 wherein the hydrocarbon completion further comprises a first bypass tubing connected to the first diverter.
 28. A hydrocarbon completion as claimed in claim 18 wherein the hydrocarbon completion further comprises a second pump system within the wellbore that is in fluid communication with the tubing string.
 29. A hydrocarbon completion as claimed in claim 28 wherein the second pump system is in fluid communication with the tubing string via the first bypass tubing.
 30. A hydrocarbon completion as claimed in claim 28 wherein the hydrocarbon completion further comprises a second diverter located between the second pump system and the tubing string.
 31. A hydrocarbon completion as claimed in claim 30 wherein the hydrocarbon completion further comprises a second bypass tubing connected to the second diverter. 